Fortuna Mining Corp. — Management Reports 2025

May 7, 2025

SATURN OIL & GAS INC.

Q1 2025 MANAGEMENT DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (“MD&A”) is a review of the operational and financial results and outlook for Saturn Oil & Gas Inc. (“Saturn” or the “Company”) as at March 31, 2025 and for the three months ended March 31, 2025 and 2024. This MD&A is dated and based on information available as at May 7, 2025 and should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“financial statements”) and the notes thereto as at March 31, 2025 and for the three months ended March 31, 2025 and 2024. Additional information relating to Saturn, including Saturn’s Annual Information Form for the year ended December 31, 2024, is available on SEDAR+ at www.sedarplus.ca and Saturn’s website at www.saturnoil.com.

Throughout this MD&A and in other materials disclosed by the Company, Saturn adheres to generally accepted accounting principles (“GAAP”) and IFRS Accounting Standards (“IFRS”) as issued by the International Accounting Standards Board (the “IASB”), however the Company also uses various specified financial measures (as defined in National Instrument 51-112 - Non-GAAP and Other Financial Measures (“NI 51-112”) including “non-GAAP financial measures”, “non-GAAP ratios”, “capital management measures” and “supplementary financial measures” to analyze financial performance including: “adjusted EBITDA”, “adjusted funds flow”, “annualized quarterly adjusted funds flow”, “free funds flow”, “capital expenditures”, “capital expenditures net of A&D”, “gross petroleum and natural gas sales”, “net operating expense”, “operating netbacks”, “operating netbacks, net of derivatives”, “adjusted working capital”, “net debt”, “net debt to annualized quarterly adjusted funds flow” and “enterprise value”. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of Saturn’s performance.

Readers are cautioned that the MD&A should be read in conjunction with disclosures in the sections entitled “Non-GAAP and Other Financial Measures” and “Advisories and forward-looking information”.

DESCRIPTION OF THE BUSINESS

Saturn is a Canadian resource company engaged in the business of acquisition, exploration and development of petroleum and natural gas resource deposits in Western Canada. The Company’s focus is to advance the development of its oil and gas properties in Alberta and Saskatchewan.

Q1 2025 HIGHLIGHTS

• Achieved record quarterly average production of 41,680 boe/d, compared to 26,394 boe/d in the first quarter of 2024 reflecting production contributions from the South Saskatchewan Acquisition in the second quarter of 2024 and new well production from the 2024 and first quarter 2025 drilling programs;
• Recognized petroleum and natural gas sales of $278.1 million, up from $168.2 million in the first quarter of 2024;
• Generated quarterly adjusted EBITDA(1) of $153.2 million, compared to $88.2 million in the first quarter of 2024;
• Achieved quarterly adjusted funds flow(1) of $131.1 million, up from $68.2 million in the first quarter of 2024;
• Invested $73.3 million in capital expenditures(1) during the first quarter of 2025, drilling 33 gross (24.4 net) wells; including 26 in Southeast Saskatchewan; 5 in West Central Saskatchewan; 1 in Southwest Saskatchewan; and 1 in Central Alberta;
• Generated free funds flow(1) of $57.8 million, up from $34.2 million in the first quarter of 2024;
• Exited the first quarter of 2025 with $813.9 million of net debt(1), equating to a net debt to annualized quarterly adjusted funds flow(1) of 1.6x;
• Repurchased 2,793,524 shares for cancellation under the Company’s Normal Course Issuer Bid (“NCIB”) at a weighted average price of $2.08 per share for a total cost of $5.8 million.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

See Non-GAAP and Other Financial Measures

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FINANCIAL AND OPERATING HIGHLIGHTS

($000s, except per share amounts)	March 31, 2025	December 31, 2024	Three months ended March 31, 2024
FINANCIAL HIGHLIGHTS
Petroleum and natural gas sales	278,081	268,845	168,219
Cash flow from operating activities	165,372	91,157	70,222
Operating netback, net of derivatives(1)	157,567	152,616	91,711
Adjusted EBITDA(1)	153,185	152,823	88,153
Adjusted funds flow(1)	131,121	129,205	68,178
per share - Basic	0.66	0.64	0.46
- Diluted	0.65	0.63	0.45
Free funds flow(1)	57,826	23,785	34,212
per share - Basic	0.29	0.12	0.23
- Diluted	0.29	0.12	0.23
Net income (loss)	37,819	(26,318)	(62,982)
per share - Basic	0.19	(0.13)	(0.42)
- Diluted	0.19	(0.13)	(0.42)
Acquisitions, net of cash acquired	-	26,011	-
Proceeds from dispositions	-	576	-
Capital expenditures(1)	73,295	105,420	33,966
Total assets	2,188,307	2,161,578	1,326,721
Net debt(1), end of period	813,893	860,155	386,417
Shareholders' equity	837,958	803,972	595,736
Common shares outstanding, end of period	196,212	199,555	161,206
Weighted average, basic	198,113	201,484	148,558
Weighted average, diluted	202,727	206,205	151,457
OPERATING HIGHLIGHTS
Average production volumes
Crude oil (bbls/d)	31,142	30,449	18,981
NGLs (bbls/d)	3,318	3,381	2,344
Natural gas (mcf/d)	43,319	43,328	30,416
Total boe/d	41,680	41,051	26,394
% Oil and NGLs	83%	82%	81%
Average realized prices
Crude oil ($/bbl)	90.48	89.13	88.64
NGLs ($/bbl)	52.95	46.74	44.24
Natural gas ($/mcf)	2.48	1.41	2.44
Processing expenses ($/boe)	(0.26)	(0.27)	(0.45)
Petroleum and natural gas sales ($/boe)	74.13	71.18	70.03
Operating netback ($/boe)
Petroleum and natural gas sales	74.13	71.18	70.03
Royalties	(9.04)	(8.71)	(8.82)
Net operating expenses(1)	(19.58)	(18.35)	(19.80)
Transportation expenses	(1.56)	(1.07)	(1.31)
Operating netback(1)	43.95	43.05	40.10
Realized loss on derivatives	(1.96)	(2.64)	(1.92)
Operating netback, net of derivatives(1)	41.99	40.41	38.18

(1) See Non-GAAP and Other Financial Measures.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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PRODUCTION

	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Crude oil (bbls/d)(1)	31,142	30,449	18,981
NGLs (bbls/d)	3,318	3,381	2,344
Natural gas (mcf/d)(1)	43,319	43,328	30,416
Total boe/d(2)	41,680	41,051	26,394
Oil and liquids %	83%	82%	81%

(1) "Crude oil" refers to light and medium crude oil and heavy crude oil combined. "Natural gas" refers to conventional natural gas. For further breakdown of crude oil and natural gas production volumes, refer to the "Product Type Information" section of this MD&A.
(2) Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities disclosed in the "Product Type Information" section of this MD&A. Also refer to the "BOE Presentation" section of this MD&A.

Production volumes increased to 41,680 boe/d for the three months ended March 31, 2025 from 26,394 boe/d in the comparative quarter of 2024. The increase is attributed to production contribution from the Flat Lake and Battrum assets acquired in June, 2024 (the "South Saskatchewan Acquisition") and new well production additions from a successful 2024 and first quarter 2025 development capital program.

Production volumes increased by 629 boe/d during the three months ended March 31, 2025 compared to the three months ended December 31, 2024, due to incremental production from wells brought on production during the first quarter, which more than offset natural declines. Production additions during the first quarter were highlighted by strong results from four new Lochend wells in Central Alberta brought on-stream in early February 2025.

The following table summarizes Saturn's average production by business unit for the three months ended March 31, 2025 and 2024:

	Three months ended March 31, 2025				Three months ended March 31, 2024
	Crude oil (bbls/d)	NGLs (bbls/d)	Natural gas (mcf/d)	Total (boe/d)	Crude oil (bbls/d)	NGLs (bbls/d)	Natural gas (mcf/d)	Total (boe/d)
Southeast Saskatchewan	18,512	1,585	7,756	21,390	10,274	789	4,420	11,800
Southwest Saskatchewan	4,684	2	192	4,718	-	-	-	-
West Central Saskatchewan	2,839	26	803	2,999	3,220	37	512	3,342
Central Alberta(1)	5,107	1,705	34,568	12,573	5,487	1,518	25,484	11,252
Total boe/d	31,142	3,318	43,319	41,680	18,981	2,344	30,416	26,394

(1) As a result of the Swan Hills Disposition, the Company aggregated the North Alberta and Central Alberta business units. Certain prior period amounts have been reclassified to conform to current presentation.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Production by Volume Three Months Ended March 31,

Production by Area Three Months Ended March 31,

Southeast Saskatchewan

The Company's core producing properties in Southeast Saskatchewan include our Oxbow assets, which are geologically concentrated within the Mississippian-aged, Midale and Frobisher oil formations and also the Bakken and Flat Lake assets geologically concentrated in the Bakken formation of Southeast Saskatchewan. For the three months ended March 31, 2025, Southeast Saskatchewan produced 21,390 boe/d, an increase of $81\%$ from 11,800 boe/d in the prior year comparative period. The increase is attributed to new well production from our 2024 and first quarter 2025 capital programs in addition to 7,889 boe/d from the Flat Lake assets acquired as part of the South Saskatchewan Acquisition.

Southwest Saskatchewan

The core producing properties in Southwest Saskatchewan include our acquired low decline oil-weighted Battrum assets, which are geologically concentrated within the Success and Roseray formations. For the three months ended March 31, 2025, Southwest Saskatchewan produced 4,718 boe/d.

West Central Saskatchewan

The core producing properties in West Central Saskatchewan consist of our Viking assets, which produced 2,999 boe/d for the three months ended March 31, 2025, compared to 3,342 boe/d in the prior year comparative period. The decrease is attributed to natural declines exceeding new well production additions on account of reduced development capital spending directed towards the West Central Saskatchewan business unit during the first quarter of 2025.

Central Alberta

The core producing properties in Central Alberta consist of our Cardium assets and our Kaybob assets located in the Montney formation. For the three months ended March 31, 2025, Central Alberta produced 12,573 boe/d, an increase of $12\%$ from 11,252 boe/d in the prior year comparative period. The increase is attributed to new well production additions in Kaybob and the Cardium, which more than offset the decrease in production volumes associated with the Deer Mountain Disposition completed in the second quarter of 2024 and natural declines.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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BENCHMARK AND REALIZED PRICES

	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Average benchmark prices
WTI (US$/bbl)(1)	71.42	70.27	76.97
Exchange rate (US$/CA$)	1.44	1.40	1.35
WTI (CA$/bbl)	102.49	98.31	103.82
MSW ($/bbl)(2)	95.34	94.90	92.17
Midale ($/bbl)(3)	92.39	91.41	86.77
LSB ($/bbl)(4)	93.62	92.55	89.59
Fosterton ($/bbl)(5)	85.42	81.72	80.94
WCS ($/bbl)(6)	84.30	80.75	77.76
AECO ($/mcf)(7)	2.16	1.48	2.51
Average realized prices
Crude oil ($/bbl)	90.48	89.13	88.64
NGLs ($/bbl)	52.95	46.74	44.24
Natural gas ($/mcf)	2.48	1.41	2.44
Processing expenses ($/boe)	(0.26)	(0.27)	(0.45)
Petroleum and natural gas sales ($/boe)	74.13	71.18	70.03

(1) West Texas Intermediate ("WTI")
(2) Mixed Sweet Blend ("MSW") Par at Edmonton
(3) Midale Par at Cromer
(4) Light Sour Blend ("LSB") Par at Cromer
(5) Fosterton Par at Regina
(6) Western Canadian Select ("WCS") at Hardisty
(7) Alberta Energy Company ("AECO") 5A Daily Index Price for natural gas

For the three months ended March 31, 2025, the Company realized an average combined price for petroleum and natural gas sales of $74.13 per boe versus $70.03 per boe in the comparative 2024 period.

Most of the Company's revenue is from the sale of crude oil which varies based on sales point and certain par prices. The Company's realized price for crude oil from Southeast Saskatchewan is primarily based on the LSB and Midale par prices at Cromer which historically trades at a small discount to the MSW par price at Edmonton. Realized prices for heavier crude oil produced by our Battrum assets in Southwest Saskatchewan are based on Fosterton which historically trades at a small premium to the WCS par price at Hardisty. Realized prices for crude oil in Central Alberta and West Central Saskatchewan are primarily based on the MSW par price at Edmonton.

The Company's average realized oil price for the three months ended March 31, 2025 was $90.48 per bbl, a 2% increase from $88.64 per bbl in the prior year comparative period. The increase in realized pricing is due to the impact of a weaker Canadian dollar on crude oil sales denominated in US dollars and narrowing Canadian crude oil differentials, despite the decrease in US$WTI crude oil benchmark price. The Company's average realized oil price increased 2% during the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to an increase in the US$WTI benchmark price combined with further weakness in the Canadian dollar.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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PETROLEUM AND NATURAL GAS SALES

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Crude oil	253,587	249,690	153,100
NGLs	15,812	14,541	9,439
Natural gas	9,651	5,637	6,751
Gross petroleum and natural gas sales(1)	279,050	269,868	169,290
Less: Processing expenses	(969)	(1,023)	(1,071)
Petroleum and natural gas sales	278,081	268,845	168,219

(1) See Non-GAAP and Other Financial Measures

Gross petroleum and natural gas sales increased for the three months ended March 31, 2025 compared to the first quarter of 2024, due primarily to increased volumes associated with the South Saskatchewan Acquisition and new well development combined with higher average realized commodity prices. Gross petroleum and natural gas sales increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to increased volumes and higher average realized prices. Certain gas processing expenses are deducted from gross realized prices received due to product custody transfer at the gas processing terminal inlet. The Company presents this on a gross and net basis to demonstrate the actual realized prices received prior to netting. The above adjustments do not have an impact on the Company's netback.

ROYALTIES

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Royalties	33,893	32,881	21,189
% of gross petroleum and natural gas sales(1)	12.1%	12.2%	12.5%
$ per boe	9.04	8.71	8.82

(1) See Non-GAAP and Other Financial Measures

Royalties increased for the three months ended March 31, 2025 compared to the first quarter of 2024, on a total basis, consistent with higher petroleum and natural gas sales. Royalties as a percentage of gross petroleum and natural gas sales decreased for the three months ended March 31, 2025 compared to the first quarter of 2024, due to the impact of royalty incentives on newer wells in Alberta. Royalties increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to increased petroleum and natural gas sales. Saturn pays royalties to the provincial governments, freehold landowners and other third parties by way of contractual overriding royalties.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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NET OPERATING EXPENSES

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Operating expenses	76,982	72,443	51,032
Less: processing income	(3,541)	(3,136)	(3,469)
Net operating expenses(1)	73,441	69,307	47,563
$ per boe	19.58	18.35	19.80

(1) See Non-GAAP and Other Financial Measures

Net operating expenses increased for the three months ended March 31, 2025 compared to the first quarter of 2024, due to higher variable costs associated with expanded field activity following the South Saskatchewan Acquisition. Net operating expenses per boe decreased for the three months ended March 31, 2025 compared to the first quarter of 2024, primarily due to increased production, as fixed costs are spread over larger production volumes. Net operating expenses increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to increased scheduled workover activity combined with higher utilities and repairs & maintenance costs associated with cold weather operating conditions.

TRANSPORTATION EXPENSES

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Transportation expenses	5,845	4,056	3,155
$ per boe	1.56	1.07	1.31

Transportation expenses increased for the three months ended March 31, 2025 compared to the first quarter of 2024, on a total basis, due to the increase in pipeline tariffs and clean oil trucking costs associated with increased crude oil production volumes. Transportation expenses increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to increased clean oil trucking costs in Southeast Saskatchewan consistent with the increase in crude oil production being trucked to various sales points. Certain pipeline shipping arrangements result in pipeline tariffs being included in transportation expenses. Conversely, pipeline tariffs incurred by commodity purchasers subsequent to delivery of the Company's product are charged back to Saturn and are netted against petroleum and natural gas sales.

RISK MANAGEMENT AND COMMODITY FINANCIAL DERIVATIVES

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Realized loss on derivatives	(7,335)	(9,985)	(4,601)
Unrealized gain (loss) on derivatives	1,688	(25,980)	(103,238)
Realized loss on derivatives
$ per boe	(1.96)	(2.64)	(1.92)

The Company uses commodity risk management contracts which are classified as financial derivatives to manage exposure to commodity price volatility. Details of open commodity contracts as at March 31, 2025 are described in the "Market Risk" section below. Realized losses occur on commodity hedge contracts when market prices for crude oil or natural gas settle at levels above those set in the Company's derivative contracts. Realized losses occur on differential hedge contracts when crude oil differentials settle at levels below those set in the Company's derivative contracts.

For the three months ended March 31, 2025, the Company realized a loss on its financial commodity contracts of $7.3 million compared to a loss of $4.6 million in the first quarter of 2024. The increased realized loss was attributed to Saturn's MSW differential hedge contracts with narrower differentials than in the prior year. The realized loss on derivatives decreased $2.7 million during the three months ended March 31, 2025 compared to the three months ended December 31, 2024, as several derivative contracts expired at the end of December 2024.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Saturn has not designated any financial commodity contracts as hedges, and as a result the unrealized gains and losses reflect the non-cash change in the mark-to-market values period over period. At March 31, 2025, the outstanding financial commodity contracts had a net liability of $41.5 million (December 31, 2024 - $43.2 million liability).

GENERAL AND ADMINISTRATIVE EXPENSES

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
General and administrative expenses	5,995	2,766	3,525
$ per boe	1.60	0.73	1.47

General and administrative ("G&A") expenses increased for the three months ended March 31, 2025, due to higher personnel and office related costs as a result of the Company's growth following the South Saskatchewan Acquisition. G&A expenses increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024, due to lower overhead recoveries.

DEPLETION, DEPRECIATION AND AMORTIZATION

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Depletion, depreciation and amortization	74,098	75,150	42,229
$ per boe	19.75	19.90	17.58

Saturn records depletion, depreciation and amortization ("DD&A") on its property, plant and equipment ("PP&E") over the useful lives of the assets employing the unit of production method using proved plus probable oil and natural gas reserves and associated future development capital required for its petroleum and natural gas assets, and a declining balance method for its corporate administrative assets.

DD&A expense increased for the three months ended March 31, 2025 compared to the first quarter of 2024, due to an increase in the carrying value of PP&E attributed to the South Saskatchewan Acquisition and associated increase in production volumes. The increase in DD&A on a per boe basis for the three months ended March 31, 2025 compared to the first quarter of 2024, reflects a higher relative increase in the depletable base compared to reserve value as a result of the South Saskatchewan Acquisition.

SHARE BASED PAYMENTS

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Share based payments	2,035	3,075	2,252
$ per boe	0.54	0.81	0.94

The Company has an omnibus Long Term Incentive Plan ("LTIP"), under which it is authorized to grant stock options, Restricted Share Units ("RSUs"), Deferred Share Units ("DSUs") and Performance Share Units ("PSUs") to directors, officers and employees of Saturn.

Share based payments expense decreased for the three months ended March 31, 2025 compared to the first quarter of 2024, due to the impact of graded vesting on annual grants of RSUs and PSUs to directors, officers and employees during the second quarter of 2024, where a greater portion of its value is expensed earlier in the life of the instrument. Share based payments expense decreased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to certain additional share based payment expenses recorded in Q4 2024.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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FINANCING EXPENSES

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Interest expense, cash	22,662	24,135	20,405
Interest income	(598)	(909)	(430)
Amortization of original issue discount and debt issue costs	784	803	674
Accretion, debt instruments	-	-	13
Accretion, leases	1,918	1,968	349
Accretion, decommissioning obligations	3,925	3,934	3,486
Financing expenses	28,691	29,931	24,497

Financing expenses increased for the three months ended March 31, 2025 compared to the first quarter of 2024, due primarily to higher debt service costs related to the Company's Senior Notes denominated in US dollars, which replaced the Company's Senior Term Loan during the second quarter of 2024. Additionally, the increase in financing expenses is due to increased accretion on leases attributed to a third party gas handling agreement entered into during the third quarter of 2024, which qualified for lease recognition and increased accretion on decommissioning obligations attributed to decommissioning obligations added as part of the South Saskatchewan Acquisition. Financing expenses decreased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to lower cash interest expense on the Company's Senior Notes associated with a reduced principal balance following the debt repayment made in the prior period.

DEFERRED TAXES

For the three months ended March 31, 2025, the Company recognized deferred tax expense of $12.8 million, compared to a deferred tax recovery of $21.1 million in the comparative 2024 period. The deferred tax expense relates to the non-cash change in the Company's deferred tax liabilities, resulting from the utilization of non-capital losses in the period.

FINANCIAL RESULTS OF OPERATIONS

($000s, except per boe amounts)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Cash flow from operating activities	165,372	91,157	70,222
per share - Basic	0.83	0.45	0.47
- Diluted	0.82	0.44	0.46
Adjusted funds flow(1)	131,121	129,205	68,178
per share - Basic	0.66	0.64	0.46
- Diluted	0.65	0.63	0.45
Free funds flow(1)	57,826	23,785	34,212
per share - Basic	0.29	0.12	0.23
- Diluted	0.29	0.12	0.23
Net income (loss)	37,819	(26,318)	(62,982)
per share - Basic	0.19	(0.13)	(0.42)
- Diluted	0.19	(0.13)	(0.42)

(1) See Non-GAAP and Other Financial Measures

Adjusted funds flow increased for the three months ended March 31, 2025 compared to the first quarter of 2024, primarily due to increased petroleum and natural gas sales, offset in part by increased royalties, increased net operating expense, increased transportation expense and an increased realized loss on derivatives. Adjusted funds flow increased during the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to increased petroleum and natural gas sales and decreased realized loss on derivatives, offset in part by increased royalties, increased net operating expenses and increased transportation expenses.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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For the three months ended March 31, 2025, the Company recorded net income of $37.8 million compared to a net loss of $63.0 million during the three months ended March 31, 2024. The increase in net income for the three months ended March 31, 2025 was primarily due to increased adjusted funds flow, an unrealized gain on derivatives compared to an unrealized loss in the prior year and an unrealized foreign exchange gain on Saturn's U.S. denominated Senior Notes, partially offset by increased DD&A.

The increase in net income for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 is primarily due to increased adjusted funds flow, an unrealized gain on derivative contracts compared to an unrealized loss in the prior quarter, an unrealized foreign exchange gain on the Company's US denominated Senior Notes compared to an unrealized loss in the prior quarter and decreased DD&A.

CAPITAL EXPENDITURES

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Drilling and Completions	54,041	76,063	23,519
Facilities	15,940	21,654	5,723
Land and lease	424	3,299	1,367
Seismic	1,368	792	355
F&D expenditures(1)	71,773	101,808	30,964
Capitalized G&A and other	1,522	3,612	3,002
Capital expenditures	73,295	105,420	33,966
Capitalized G&A and other	(1,522)	(3,612)	(3,002)
Property acquisitions	-	26,011	-
Property disposition	-	576	-
FD&A expenditures(1)	71,773	128,395	30,964

(1) See Non-GAAP and Other Financial Measures

Capital expenditures increased for the three months ended March 31, 2025, due to an increased drilling program and increased facility infrastructure development on Saturn's expanded asset base resulting from the South Saskatchewan Acquisition. During the first quarter of 2025, the Company's operated drilling program was heavily focused on development of acquired locations in Southeast Saskatchewan. Facility expenditures during the first quarter of 2025 included continued investment in our waterflood projects.

Capital expenditures decreased during the three months ended March 31, 2025 compared to the three months ended December 31, 2024 due to a reduction in drilling and completion expenditures directed towards higher cost wells in Central Alberta, in addition to reduced facilities spending as the majority of large infrastructure projects were completed by the end of 2024, including construction of a new treating facility and gathering system in West Central Saskatchewan and pipeline expansion projects within the acquired Flat Lake and Battrum properties.

During the three months ended March 31, 2025, the Company drilled 33 gross (24.4 net) wells: 26 in Southeast Saskatchewan; five in West Central Saskatchewan; one in Southwest Saskatchewan; and one in Central Alberta compared to 9 gross (8.3 net) wells in the prior year comparative period: six in Southeast Saskatchewan; and three in Central Alberta.

	Three months ended March 31,
	2025		2024
	Gross	Net	Gross	Net
Wells drilled	33	24.4	9	8.3

CAPITAL RESOURCES AND LIQUIDITY

Senior Notes

The Company has US$601.3 million of Senior Notes outstanding. The Senior Notes bear interest at 9.625% per annum, payable semi-annually in arrears, have mandatory prepayments of 10% per annum, payable quarterly, and have a 5-year term maturing on June 15, 2029. As at March 31, 2025, the principal balance on the Senior Notes was $864.4 million

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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(US$601.3 million). The mandatory prepayments are due quarterly, no later than 30 days after the end of each fiscal quarter, beginning September 30, 2024 at a redemption price of 104.813%.

Subsequent to March 31, 2025, the Company repurchased an additional $15.0 million of Senior Notes for retirement.

Revolving Credit Facility

On June 14, 2024, Saturn entered into a $150.0 million credit facility with a syndicate of banks, which is secured by a first priority security interest on all present and after acquired property of the Company and is senior in priority to the Senior Notes. The new facility consists of a $100.0 million reserve-based credit facility and a $50.0 million operating facility, (together the "Credit Facility"), which is committed and available on a revolving basis until June 14, 2026, at which time it may be extended at the lenders' option. The Credit Facility is subject to a semi-annual borrowing base review, occurring by June 30th and November 30th of each year, with the first borrowing base review to occur by June 30, 2025.

Amounts borrowed under the Credit Facility bear interest at a floating rate based on the applicable Canadian prime rate, US base rate, Canadian Overnight Repo Rate Average ("CORRA"), or Secured Overnight Financing Rate ("SOFR") plus a margin and standby fee based on the Company's Net Debt to Consolidated EBITDA Ratio as defined in the Credit Agreement, currently between 2.50% to 3.50% and 0.88%, respectively.

As at March 31, 2025 and the date of this MD&A, the Company had no amounts drawn nor any of letters of credit outstanding under the Credit Facility.

Unsecured Letter of Credit Facility

The Company has a $20.0 million unsecured demand letter of credit facility (the "LC Facility") with a Canadian bank. Saturn's obligations under the LC Facility are supported by a performance security guarantee ("PSG") from Export Development Canada. At March 31, 2025, $8.7 million was drawn under the LC Facility (December 31, 2024 – $7.9 million). The PSG is subject to annual renewal with the next scheduled renewal date of June 30, 2025.

Liquidity

($000s)	March 31, 2025	December 31, 2024
Credit Facility^{(1)}	150,000	150,000
LC Facility^{(2)}	11,300	12,100
Adjusted working capital surplus^{(3)}	37,315	14,433
Total Liquidity	198,615	176,533

(1) Represents $nil drawn on the $150.0 million Credit Facility.
(2) Represents $8.7 million drawn on the $20.0 million LC Facility (December 31, 2024 - $7.9 million).
(3) Adjusted working capital is calculated as cash, accounts receivable, deposits and prepaids net of accounts payable.

The Company relies on a combination of internal profitability measured by adjusted funds flow, undrawn balance on its Credit Facility, debt financing and equity issuances to fund its capital requirements and provide liquidity. To the extent possible, Saturn has attempted to mitigate certain risks by entering into financial derivative commodity contracts to reduce the financial impact of downward commodity price movements on a portion of the Company's anticipated production. Future liquidity depends primarily on profitability and the ability to access debt and equity markets. All principal repayments on the Senior Notes that are due within twelve months are presented as current liabilities on the balance sheet with the remainder classified as non-current. The Company believes that the capital structure of the Company coupled with the projected adjusted funds flow will satisfy Saturn's continuing operations.

Discussion of all equity offerings completed by the Company in 2025 are described in "Share Capital" section below.

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MANAGEMENT DISCUSSION & ANALYSIS

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Net Debt, Enterprise Value and Leverage

Management considers net debt a key measure in assessing the Company's liquidity. Saturn's net debt totaled $813.9 million as at March 31, 2025 compared to $860.2 million as at December 31, 2024. The Company's net debt to annualized quarterly adjusted funds flow was 1.6x at March 31, 2025.

($000s)	March 31, 2025	December 31, 2024
Net debt^{(1)}	813,893	860,155
Total market capitalization^{(2)}	384,576	431,039
Enterprise value^{(1)}	1,198,469	1,291,194
Net debt as a percentage of enterprise value	68%	67%
Annualized quarterly adjusted funds flow^{(1)}	524,484	516,820
Net debt to annualized quarterly adjusted funds flow	1.6x	1.7x

(1) See Non-GAAP and Other Financial Measures.
(2) Calculated as 196,211,573 Common Shares outstanding multiplied by the TSX closing share price on the last day of trading of the period.

Off-balance Sheet Transactions

The Company is not party to any material arrangements that would be excluded from the balance sheets other than disclosed in the commitments section of this MD&A.

SHARE CAPITAL

The Company is authorized to issue an unlimited number of Common Shares without par value.

On August 23, 2024, the TSX approved the commencement of the Company's Normal Course Issuer Bid ("NCIB"). Pursuant to the NCIB, the Company will purchase for cancellation, from time to time, as it considers advisable, up to a maximum of 11,306,825 Common Shares between August 27, 2024 and August 26, 2025.

For the three months ended March 31, 2025, the Company repurchased 2,793,524 Common Shares under its NCIB at a weighted average price of $2.08 per share for a total cost of $5.8 million. Subsequent to March 31, 2025, the Company repurchased an additional 1,084,004 Common Shares at a weighted average price of $1.56 per share for a total cost of $1.7 million.

As at the date of this MD&A, March 31, 2025 and December 31, 2024, the following Common Shares are outstanding and/or remain issuable upon exercise of the underlying securities.

(000s) Number of securities	May 7, 2025	March 31, 2025	December 31, 2024
Common Shares outstanding	195,841	196,212	199,555
Warrants^{(1)}	-	-	6,871
Performance warrants	7,000	7,000	7,000
Restricted share units	8,987	3,988	4,088
Stock options	689	714	718
Deferred share unit	387	-	-
Performance share units	1,868	622	622
Fully diluted shares outstanding	214,772	208,536	218,854

(1) Warrants expired on March 10, 2025

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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COMMITMENTS AND CONTRACTUAL OBLIGATIONS

The Company has the following contractual obligations and commitments as at May 7, 2025:

($000s)	Less than 1 year	1-3 years	3-5 years	Greater than 5 years	Total
Senior Notes(1)	93,444	186,888	584,024	-	864,356
Interest payments(2)	86,839	146,728	84,593	-	318,160
Lease liabilities(3)	6,315	8,373	5,780	61	20,529
Gas processing contracts	12,569	23,045	21,358	50,045	107,017
	199,167	365,034	695,755	50,106	1,310,062

(1) Represents the remaining principal amount owing of US$601.3 million on the Company's Senior Notes converted at the period end exchange rate of 1.4376
(2) The Senior Notes bear interest at 9.625% per annum, payable semi-annually in arrears, have mandatory prepayments of 10% per annum, payable quarterly.
(3) Represents the remaining undiscounted minimum lease payments on the Company's lease liabilities, excluding gas processing contracts subject to IFRS 16

RISKS AND UNCERTAINTIES

Factors beyond Saturn's control may determine whether any oil and gas reserves the Company discovers are sufficiently economic to be developed. The determination of whether petroleum and natural gas deposits are economic is affected by numerous factors beyond Saturn's control. These factors include market fluctuations for oil and gas; the costs of access and surface rights; and government regulations governing prices, taxes, royalties, land tenure, land use, importing and exporting of resources and environmental protection.

Land reclamation requirements for exploration and development properties may be burdensome. Although variable depending on location and the governing authority, land reclamation requirements are generally imposed on companies in extractive industries such as oil and gas or mining in order to minimize long-term effects of land disturbance. Reclamation may include requirements to control dispersion of potentially deleterious effluents and reasonably re-establish predisturbance landforms and vegetation. In order to carry out reclamation obligations imposed on the Company in connection with ongoing exploration and development, Saturn must allocate financial resources that might otherwise be spent on further exploration and development programs.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. While the Company is exposed to liquidity risk, that risk is actively managed through strategies such as prudent capital spending, an active commodity risk management program; shown in the market risk section below, and by continuously monitoring forecast and actual cash flows from operating, financing and investing activities. Management believes it will have sufficient funding to meet foreseeable liquidity requirements.

Credit Risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations that arise principally from the Company's accounts receivable from oil and natural gas marketers and joint operators in the oil and gas industry. Receivables from oil and natural gas marketers are normally collected on the 25th day of the month following production.

The Company's policy to mitigate credit risk going forward is to maintain marketing relationships with large, established and reputable purchasers that are considered to be creditworthy. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital and operating expenditures prior to expenditure and in certain circumstances may require cash deposits in advance of incurring financial obligations on behalf of joint venture partners. Joint venture receivables are from partners in the petroleum and natural gas industry who are subject to the risks and conditions of the industry. Significant changes in industry conditions and risks that negatively impact partners' ability to generate cash flow will increase the risk of not collecting receivables. The Company does not request letters of credit in its favor from joint venture partners; however the Company has the ability to withhold production from joint operating partners in the event of non-payment or is able to register security on the assets of joint operating partners.

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Counterparties to financial instruments expose the Company to credit losses in the event of non-performance. Counterparties for derivative instrument transactions are limited to investment grade counterparties.

Currency Risk

Currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. All of the Company's petroleum and natural gas sales are conducted in Canada and are denominated in Canadian dollars. Canadian commodity prices are influenced by fluctuations in the Canada to US dollar exchange rate. Prices for oil are determined in global markets and generally denominated in US dollars. The Company is exposed to currency risk in relation to its US dollar denominated financial derivatives and Senior Notes. A ten percent change in the US dollar would have resulted in a $89.2 million change to net income (loss) before tax (December 31, 2024 – $89.4 million) assuming all other variables remain constant. The exposure of realized price fluctuations of the US dollar and Canadian dollar exchange rate, serves as a natural hedge to US dollar denominated financial derivatives.

The Company is exposed to currency risk in relation to its US dollar denominated Senior Notes. To mitigate its exposure to changes in the Canadian to US dollar exchange rate, the Company has entered into foreign exchange contracts with respect to its US denominated interest and principal repayments.

The Company had the following outstanding foreign exchange contracts as at May 7, 2025:

	Forward Rate Contracts- USD/CAD
Period	Notional Amount ($000s, US$)	Rate	Contract Type
Q2 2025	46,600	1.33935	Average rate currency swap
Q3 2025	17,100	1.33935	Average rate currency swap
Q4 2025	45,000	1.33935	Average rate currency swap
Q1 2026	17,100	1.33935	Average rate currency swap
Q2 2026	43,500	1.33935	Average rate currency swap
Q3 2026	17,100	1.33935	Average rate currency swap
Q4 2026	41,900	1.33935	Average rate currency swap
Q1 2027	17,100	1.33935	Average rate currency swap
Q2 2027	23,300	1.33935	Average rate currency swap

Price Risk

The Company is exposed to price risk related to commodity and equity prices. Equity price risk is the potential adverse impact on the Company's earnings due to movements in individual equity prices or general movements in the level of the stock market. Commodity price risk is the potential adverse impact on earnings and economic value due to commodity price movements and volatility. The Company's commodity price risk is also impacted by its derivative contracts. The ability of the Company to explore its resource properties and future profitability of the Company are directly related to the market price of commodities. Prices for oil are impacted not only by the relationship between the Canadian and United States dollars but also worldwide economic events that influence supply and demand.

Market Risk

Saturn manages the risks associated with changes in commodity prices by entering into a variety of risk management commodity contracts classified as financial derivatives. The Company assesses the effects of movement in commodity prices on income before tax. A ten percent increase or decrease in commodity prices would have resulted in a $55.4 million change to unrealized gains or (losses) on risk management contracts and net income (loss) before tax assuming all other variables remain constant.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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The Company had the following outstanding financial derivative commodity contracts as at May 7, 2025:

	WTI Collars				WTI Swaps				NGL Propane Swaps
Period	Volume bbls/d	Price(1)(2) US$/bbl	Volume bbls/d	Price(1) CA/bbl	Volume bbls/d	Price(1) US$/bbl	Volume bbls/d	Price(1) CA$/bbl	Volume bbls/d	Price(1) US$/bbl
Q2 2025	8,456	63.41-83.51	5,000	100.00-110.00	1,707	70.52	1,136	92.56	251	49% WTI
Q3 2025	6,729	67.23-84.37	5,000	100.00-110.00	2,753	69.05	4,923	89.10	375	49% WTI
Q4 2025	1,684	65.00-68.10	5,000	100.00-110.00	2,637	68.99	4,674	89.05	375	49% WTI
Q1 2026	1,080	65.00-68.10	-	-	3,077	67.21	4,481	85.46	375	49% WTI
Q2 2026	-	-	-	-	4,028	67.30	4,320	85.47	-	-
Q3 2026	-	-	-	-	-	-	4,649	83.51	-	-
Q4 2026	-	-	-	-	-	-	4,463	83.47	-	-
Q1 2027	-	-	-	-	-	-	-	-	-	-

(1) Weighted average prices for the period.
(2) For the reporting periods Q1 2025 to Q4 2025, the Company has a weighted average option premium of US$2.41/bbl.

	WTI/MSW Differential		WTI/WCS Differential		Natural Gas Swaps
Period	Volume bbls/d	Price(1) US$/bbl	Volume bbls/d	Price(1) US$/bbl	Volume GJ/d	Price(1) CA$/GJ	Volume GJ/d	Price(2) CA$/GJ
Q2 2025	15,746	(4.61)	3,489	(15.36)	15,000	2.49	10,550	Index
Q3 2025	15,500	(3.60)	4,000	(12.91)	15,000	2.49	10,550	Index
Q4 2025	4,000	(5.00)	4,000	(13.95)	11,685	2.62	10,550	Index
Q1 2026	-	-	-	-	10,000	2.73	10,550	Index
Q2 2026	-	-	-	-	15,000	2.69	10,550	Index
Q3 2026	-	-	-	-	15,000	2.69	10,550	Index
Q4 2026	-	-	-	-	18,315	2.95	3,555	Index
Q1 2027	-	-	-	-	10,000	3.35	-	-

(1) Weighted average prices for the period.
(2) Physically settled derivative contracts based off US natural gas index prices (Malin index minus US$1.98/GJ minus AECO 5A) and (NW Rocky index minus US$1.99/GJ minus AECO 5A).

General Risks

Petroleum and natural gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitat, as well as safety risks such as personal injury. The Company works hard to identify the potential environmental impacts of its new projects in the planning stage and during operations. The Company conducts its operations with high standards in order to protect the environment, its employees and consultants, and the general public. Saturn maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations. Without such insurance, and if the Company becomes subject to environmental liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the funds the Company has available and result in financial distress.

Climate Change Risks

Saturn's exploration and production infrastructure and other operations and activities emit greenhouse gasses ("GHG") which may require the Company to comply with federal and/or provincial GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate the effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Some of Saturn's significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, climate change has been linked to long-term shifts in climate patterns and extreme weather conditions both of which pose the risk of causing operational difficulties.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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SUMMARY OF QUARTERLY RESULTS

	2025	2024				2023
($000s, except per boe amounts)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Financial:
Petroleum and natural gas sales	278,081	268,845	262,379	208,853	168,219	185,384	201,066	176,034
Cash flow from operations	165,372	91,157	100,013	50,545	70,222	75,380	70,466	94,232
Adjusted funds flow(1)	131,121	129,205	94,065	88,643	68,178	80,247	76,477	66,954
Basic ($/share)	0.66	0.64	0.46	0.52	0.46	0.58	0.55	0.48
Diluted ($/share)	0.65	0.63	0.45	0.51	0.45	0.56	0.54	0.47
Net income (loss)	37,819	(26,318)	101,601	41,805	(62,982)	131,456	(111,156)	51,273
Basic ($/share)	0.19	(0.13)	0.50	0.25	(0.42)	0.94	(0.80)	0.37
Diluted ($/share)	0.19	(0.13)	0.49	0.24	(0.42)	0.92	(0.80)	0.36
Acquisitions	-	26,011	(4,749)	543,145	-	-	-	1,439
Dispositions	-	576	-	(25,708)	-	-	-	-
Capital expenditures(1)	73,295	105,420	84,381	22,549	33,966	57,175	35,271	13,845
Total assets	2,188,307	2,161,578	2,155,632	2,024,432	1,326,721	1,335,216	1,376,271	1,332,816
Common shares outstanding (000s)	196,212	199,555	203,103	204,041	161,206	139,313	139,313	138,634
Operational:
Average daily production
Crude oil (bbls/d)	31,142	30,449	28,994	21,010	18,981	19,407	19,132	19,425
NGLs (bbls/d)	3,318	3,381	3,407	2,673	2,344	2,533	2,287	2,137
Natural gas (mcf/d)	43,319	43,328	39,885	38,664	30,416	29,704	29,077	26,553
Total (boe/d)	41,680	41,051	39,049	30,127	26,394	26,891	26,265	25,988

(1) See Non-GAAP and Other Financial Measures

In the first quarter of 2025, the Company achieved record adjusted funds flow of $131.1 million driven by record quarterly production of 41,680 boe/d and an operating netback, net of derivatives of $41.99 per boe. The Company invested $73.3 million in capital expenditures, drilling 33 wells (24.4 net). The Company repurchased 2,793,524 Common Shares for cancellation under its NCIB at a weighted average price of $2.08 per share for a total cost of $5.8 million. The Company made principal repayments of $23.2 million (US$16.3 million) on the Senior Notes, reducing net debt to $813.9 million. Changes in quarterly sales, pricing, production, net income, cash flow from operations, adjusted funds flow and capital expenditures are all discussed in the previous sections of this MD&A.

In the fourth quarter of 2024, the Company closed the Brazeau Acquisition for $20.5 million. The Company achieved adjusted funds flow of $129.2 million driven by quarterly production of 41,051 boe/d and an operating netback, net of derivatives of $40.41 per boe. The Company invested a record $105.4 million in capital expenditures, drilling 33 wells (26.2 net). The Company repurchased 3,385,052 Common Shares for cancellation under its NCIB at a weighted average price of $2.21 per share for a total cost of $7.5 million. The Company made principal repayments of $23.4 million (US$16.3 million) on the Senior Notes, reducing net debt to $860.2 million.

In the third quarter of 2024, the Company achieved adjusted funds flow of $94.1 million driven by quarterly production of 39,049 boe/d in the first full quarter following the South Saskatchewan Acquisition. The Company invested $84.4 million in capital expenditures, drilling 48 wells (41.2 net). The Company received TSX approval for the commencement of the NCIB and repurchased 1,095,236 Common Shares for cancellation at a weighted average price of $2.50 per share for a total cost of $2.7 million. The Company's initial principal repayment of US$16.3 million was made on the Senior Notes, reducing net debt to $779.0 million.

In the second quarter of 2024, the Company closed the Adonai Acquisition for $8.3 million, closed the South Saskatchewan Acquisition for cash consideration of $534.8 million and closed the non-core Deer Mountain Disposition for net cash proceeds of $25.7 million. Concurrent with the acquisitions, the Company completed a refinancing issuing US$650 in Senior Notes, closed a $100.0 million equity financing and extinguished it's Senior Term Loan. The Company realized adjusted

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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funds flow of $88.6 million and invested $22.5 million in capital expenditures. The Company generated quarterly petroleum and natural gas sales of $208.9 million, driven primarily by record average production of 30,127 boe/d.

In the first quarter of 2024, the Company achieved adjusted funds flow of $68.2 million driven by strong production of 26,394 boe/d and an operating netback, net of derivatives of $38.18 per boe. The Company invested $34.0 million in capital expenditures, drilling 9 wells (8.3 net). Principal repayments on the Senior Term Loan of $76.1 million were made resulting in net debt of $386.4 million. The Company enhanced liquidity with the completion of a bought-deal equity financing, issuing 22,223,000 Common Shares for gross proceeds of $50.0 million.

In the fourth quarter of 2023, the Company achieved record adjusted funds flow of $80.2 million driven by record production of 26,891 boe/d and an operating netback, net of derivatives of $42.17 per boe. The Company invested $57.2 million in capital expenditures, drilling 19 wells (16.9 net). Principal repayments on the Senior Term Loan of $50.7 million were made resulting in net debt of $460.5 million.

In the third quarter of 2023, the Company achieved adjusted funds flow of $76.5 million driven by production of 26,265 boe/d and an operating netback, net of derivatives of $43.74 per boe. The Company invested $35.3 million in capital expenditures, drilling 20 wells (15.7 net). Principal repayments on the Senior Term Loan of $50.7 million were made resulting in net debt of $473.8 million.

In the second quarter of 2023, despite the Alberta wildfires impacting operations, the Company achieved adjusted funds flow of $67.0 million driven by production of 25,988 boe/d and an operating netback, net of derivatives of $41.87 per boe. The Company made $50.7 million in principal repayments on the Senior Term Loan and invested $13.8 million in capital expenditures resulting in an ending net debt balance of $510.2 million.

STANDARDS ISSUED BUT NOT YET EFFECTIVE

In April 2024, the International Accounting Standards Board ("IASB") issued IFRS 18 Presentation and Disclosure in Financial Statements which replaces IAS 1 Presentation of Financial Statements effective for annual reporting periods beginning on or after January 1, 2027 and is required to be adopted retrospectively with early adoption permitted. The standard introduces a defined structure to the Statement of Net Income and Comprehensive Income with related specific disclosure requirements. The Company is assessing the impact of IFRS 18 on its consolidated financial statements.

INTERNAL CONTROLS OVER FINANCIAL REPORTING ("ICFR")

ICFR is a set of processes designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized, and facilitate the preparation of relevant, reliable, and timely information. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Management has designed and assessed the effectiveness of Saturn's ICFR as defined in Canada by National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"). The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. NI 52-109 requires that Saturn disclose in its MD&A any material weaknesses relating to design existing at the end of the period in Saturn's ICFR and/or any changes in Saturn's ICFR that occurred during the period that have materially affected, or are reasonably likely to materially affect, Saturn's ICFR. Management confirms there were no changes in Saturn's ICFR during the period ended March 31, 2025 that materially affected, or are reasonably likely to materially affect, the Company's ICFR.

USE OF ESTIMATES

The Company makes estimates and assumptions about the future that affect the reported amounts of assets and liabilities. Estimates and judgments are continually evaluated based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. In the future, actual experience may differ from these estimates and assumptions.

The effect of a change in an accounting estimate is recognized prospectively by including it in profit or loss in the period of the change, if the change affects that period only, or in the period of the change and future periods, if the change affects both.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Significant assumptions about the future and other sources of estimation uncertainty that management has made at the balance sheets date, that could result in a material adjustment to the carrying amounts of assets and liabilities, in the event that actual results differ from assumptions made relate to, but are not limited to, the following:

• The recoverability of accounts receivable, which is included in the consolidated balance sheets;
• The determination of the fair value of stock options, RSUs, PSUs, or warrants using stock pricing models requires the input of highly subjective assumptions, including the expected price volatility. Changes in the subjective input assumptions could materially affect the fair value estimate; therefore, the existing models do not necessarily provide a reliable single measure of the fair value of the Company's outstanding stock based compensation;
• Fair values of petroleum and natural gas properties, depletion and depreciation expense and amounts used in impairment calculations are based on estimates of proved and probable oil and gas reserves are based upon a number of significant assumptions, such as forecasted production volumes, forecasted oil and gas commodity prices, forecasted operating costs, forecasted royalty costs and forecasted future development costs. By their nature, estimates of proved and probable oil and gas reserves and the related future cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the consolidated financial statements of future periods could be material;
• Amounts recorded for asset retirement obligation liabilities including estimates around timing and amount of expenditures required to settle liabilities and the credit-adjusted risk free discount rate used;
• Financial derivative commodity and foreign exchange contracts are valued using valuation techniques with market observable inputs. The most frequently applied valuation techniques include Black-Scholes valuation model and forward pricing and swap models. The models incorporate various inputs including the credit quality of counterparties, forecast benchmark commodity prices, and foreign exchange; and
• The determination of the estimated acquisition-date fair value of oil and gas properties involves significant estimates, including proved and probable oil and gas reserves and discount rates. The estimate of proved and probable reserves includes significant assumptions related to forecasted oil and gas commodity prices, forecasted production volumes, forecasted operating costs, forecasted royalty costs and forecasted future development costs. Changes in the assumptions or estimates used in determining the estimated acquisition date fair value of the acquired assets and liabilities could impact the allocation of the purchase price between assets and liabilities recorded on the balance sheets and revenue and expenses recorded on the statement of comprehensive income (loss).
• The determination of income tax liabilities includes estimates around future utilization of tax pools. All tax filings are subject to audit and potential reassessment after the lapse of considerable time.

NON-GAAP AND OTHER FINANCIAL MEASURES

Throughout this MD&A and in other materials disclosed by the Company, Saturn employs certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of Saturn's performance.

Non-GAAP Financial Measures and Ratios

NI 52-112 defines a non-GAAP financial measure as a financial measure that: (i) depicts the historical or expected future financial performance, financial position or cash flow of an entity, (ii) with respect to its composition, excludes an amount that is included in, or includes an amount that is excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the entity, (iii) is not disclosed in the financial statements of the entity, and (iv) not a ratio, fraction, percentage or similar representation. NI 52-112 defines a non-GAAP ratio as a financial ratio that: (i) is in the form of a ratio, fraction, percentage or similar representation, (ii) has a non-GAAP financial measure as one or more of its components, and (iii) is not disclosed in the financial statements of the entity. The Company has presented the following non-GAAP financial measures and ratios within this MD&A.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Capital Expenditures

Saturn uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. Saturn's capital budget excludes acquisition and disposition activities as well as the accounting impact of any accrual changes or payments under certain lease arrangements. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. The following table reconciles capital expenditures and capital expenditures, net A&D to the nearest GAAP measure, cash flow used in investing activities.

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Cash flow used in investing activities	99,520	114,533	49,692
Change in non-cash working capital	(26,225)	17,474	(15,726)
Capital expenditures, net A&D	73,295	132,007	33,966
Acquisitions, net of cash acquired	-	(26,011)	-
Proceeds from disposition	-	(576)	-
Capital expenditures	73,295	105,420	33,966

F&D and FD&A Expenditures

Saturn uses finding and development ("F&D") and finding, development, and acquisition ("FD&A") expenditures as a basis to monitor its capital efficiency. The Company's F&D expenditures are calculated by removing certain capitalized overhead costs from capital expenditures. The Company's FD&A expenditures are calculated by adding A&D to FD&A expenditures. Both measures calculate the capital cost outlay associated with the Company's exploration and development activities for the purposes of finding, developing and, when desired, acquiring its reserves.

Free Funds Flow

Saturn uses free funds flow as an indicator of the efficiency and liquidity of its business, measuring its funds after capital investment available to manage debt levels, pursue acquisitions and gauge optionality to pay dividends and/or and return capital to shareholders through activities such as share repurchases. Saturn calculates free funds flow as adjusted funds flow in the period less capital expenditures. By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions. The following table reconciles adjusted funds flow to free funds flow.

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Adjusted funds flow	131,121	129,205	68,178
Capital expenditures	(73,295)	(105,420)	(33,966)
Free funds flow	57,826	23,785	34,212

Gross Petroleum and Natural Gas Sales

Gross petroleum and natural gas sales is calculated by adding crude oil, natural gas and NGLs revenue, before deducting certain gas processing expenses in arriving at petroleum and natural gas revenue as required under IFRS 15. These processing expenses associated with the processing of natural gas and NGLs revenue are a result of the Company transferring custody of the product at the terminal inlet, and therefore receiving net prices. This metric is used by management to quantify and analyze the realized price received before required processing deductions, against benchmark prices. The calculation of the Company's gross petroleum and natural gas sales is shown within the petroleum and natural gas sales section within this MD&A.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Net Operating Expenses

Net operating expense is calculated by deducting processing income primarily generated by processing third party production at processing facilities where the Company has an ownership interest, from operating expenses presented on the Statement of income (loss). Where the Company has excess capacity at one of its facilities, it will process third-party volumes to reduce the cost of ownership in the facility. The Company's primary business activities are not that of a midstream entity whose activities are focused on earning processing and other infrastructure-based revenues, and as such third-party processing revenue is netted against operating expenses in the MD&A. This metric is used by management to evaluate the Company's net operating expenses on a unit of production basis. Net operating expense per boe is a non-GAAP financial ratio and is calculated as net operating expense divided by total barrels of oil equivalent produced over a specific period of time. The calculation of the Company's net operating expenses is shown within the net operating expenses section within this MD&A.

Operating Netback and Operating Netback, Net of Derivatives

The Company's operating netback is determined by deducting royalties, net operating expenses and transportation expenses from petroleum and natural gas sales. The Company's operating netback, net of derivatives is calculated by adding or deducting realized financial derivative commodity contract gains or losses from the operating netback. Derivative contract termination payments are excluded from realized financial derivative commodity contract gains or losses for the purposes of calculating the operating netback. The Company's operating netback and operating netback, net of derivatives are used in operational and capital allocation decisions. Presenting operating netback and operating netback, net of derivatives on a per boe basis is a non-GAAP financial ratio and allows management to better analyze performance against prior periods on a per unit of production basis. The calculation of the Company's operating netbacks and operating netback, net of derivatives are summarized as follows.

($000s)	Three months ended
	March 31, 2025	December 31, 2024	March 31, 2024
Petroleum and natural gas sales	278,081	268,845	168,219
Royalties	(33,893)	(32,881)	(21,189)
Net operating expenses	(73,441)	(69,307)	(47,563)
Transportation expenses	(5,845)	(4,056)	(3,155)
Operating netback	164,902	162,601	96,312
Realized loss on financial derivatives(1)	(7,335)	(9,985)	(4,601)
Operating netback, net of derivatives	157,567	152,616	91,711
($ per boe amounts)
Petroleum and natural gas sales	74.13	71.18	70.03
Royalties	(9.04)	(8.71)	(8.82)
Net operating expenses	(19.58)	(18.35)	(19.80)
Transportation expenses	(1.56)	(1.07)	(1.31)
Operating netback	43.95	43.05	40.10
Realized loss on financial derivatives	(1.96)	(2.64)	(1.92)
Operating netback, net of derivatives	41.99	40.41	38.18

(1) Includes early termination payment on certain WTI oil derivative contracts for the three months ended December 31, 2024 of $0.4 million.

Enterprise value

The Company's enterprise value is calculated as total market capitalization plus net debt. Enterprise value is used to assess the valuation of the Company. Refer to the Liquidity and Capital Resources section in this MD&A for further information.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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Capital Management Measures

NI 52-112 defines a capital management measure as a financial measure that: (i) is intended to enable an individual to evaluate an entity's objectives, policies and processes for managing the entity's capital; (ii) is not a component of a line item disclosed in the primary financial statements of the entity; (iii) is disclosed in the notes to the financial statements of the entity; and (iv) is not disclosed in the primary financial statements of the entity. Please refer to note 16 "Capital Management" in Saturn's financial statements for additional disclosure on: adjusted working capital, net debt, adjusted EBITDA, adjusted funds flow, free funds flow, annualized quarterly adjusted funds flow and net debt to annualized quarterly adjusted funds flow each of which are capital management measures used by the Company in this MD&A.

Supplementary Financial Measures

NI 52-112 defines a supplementary financial measure as a financial measure that: (i) is, or is intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of an entity; (ii) is not disclosed in the financial statements of the entity; (iii) is not a non-GAAP financial measure; and (iv) is not a non-GAAP ratio. The supplementary financial measures used in this MD&A are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.

Product Type Information

The Company's aggregate average production for the past eight quarters and the references to "crude oil", "NGLs", and "natural gas" reported in this MD&A consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 1 Bbl : 6 Mcf where applicable:

	2025	2024				2023
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Average daily production
Light & medium crude oil (bbls/d)	27,697	27,330	24,992	18,346	18,981	19,407	19,132	19,425
Heavy crude oil (bbls/d)	3,445	3,119	4,002	2,664	-	-	-	-
NGLs (bbls/d)	3,318	3,381	3,407	2,673	2,344	2,533	2,287	2,137
Conventional natural gas (mcf/d)	43,319	43,328	39,885	38,664	30,416	29,704	29,077	26,553
Total (boe/d)	41,680	41,051	39,049	30,127	26,394	26,891	26,265	25,988

BOE PRESENTATION

Boe means barrel of oil equivalent. All boe conversions in this MD&A are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The information provided in this report, including the financial statements, is the responsibility of management. In the preparation of these statements, estimates are sometimes necessary in the determination of future values for certain assets or liabilities. Management believes such estimates have been based on careful judgments and have been properly reflected in the financial statements.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS

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DIRECTORS AND EXECUTIVE OFFICERS

As of the date of this report the Company had the following directors and executive officers:

John Jeffrey	Chief Executive Officer and Director
Scott Sanborn	Chief Financial Officer
Justin Kaufmann	Chief Development Officer
Grant MacKenzie	Chief Legal Officer and Director
Andrew Claugus	Director
Thomas Gutschlag	Director
Ivan Bergerman	Director
Jim Payne	Director
Christopher Ryan	Director
S. Janet Yang	Director

ADVISORIES AND FORWARD-LOOKING INFORMATION

Certain information in this MD&A, including all statements that are not historical facts, constitutes forward-looking information within the meaning of applicable Canadian securities laws. Such forward-looking information may include, but is not limited to, information which reflect management's expectations regarding the Company's future growth, the effects of the Company's acquisitions and dispositions on the Company's strategy, land holdings and profitability, the continued availability of adequate debt and equity financing and funds flow to fund the Company's planned expenditures, results of operations (including, without limitation, future production and capital expenditures), performance (both operational and financial), the impact of hedging on the Company's operations and business prospects (including the timing and development of new reserves and the success of exploration activities) and opportunities. Often, this information includes words such as "plans", "expects" or "does not expect", "is expected", "budget", "scheduled", "estimates", "forecasts", "intends", "anticipates" or "does not anticipate" or "believes" or variations of such words and phrases or statements that certain actions, events or results "may", "could", "would", "might" or "will" be taken, occur or be achieved.

In making and providing the forward-looking information included in this MD&A the Company's assumptions may include among other things: (i) that there are no material delays in the optimization of operations at the properties; (ii) assumptions about operating costs and expenditures; (iii) assumptions about future production recovery and cash flows; (iv) that there is no unanticipated fluctuation in foreign exchange rates; (v) the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration, and (vi) that there is no material deterioration in general economic conditions. Although management believes that the assumptions made and the expectations represented by such information are reasonable, there can be no assurance that the forward-looking information will prove to be accurate. By its nature, forward-looking information is based on assumptions and involves known and unknown risks, uncertainties and other factors that may cause the Company's actual results, performance or achievements, or results, to be materially different from future results, performance or achievements expressed or implied by such forward-looking information. Such risks, uncertainties and other factors include among other things the following: (i) the risk that additional financing will not be obtained as and when required; (ii) material increases in operating costs; (iii) adverse fluctuations in foreign exchange rates; (iv) commodity price fluctuations; and (v) environmental risks and changes in environmental legislation.

This MD&A (See "Risks and Uncertainties") contains information on risks, uncertainties and other factors relating to the forward-looking information. Although the Company has attempted to identify factors that would cause actual actions, events or results to differ materially from those disclosed in the forward-looking information, there may be other factors that cause actual results, performances, achievements or events not to be anticipated, estimated or intended. Also, many of the factors are beyond the Company's control. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to reissue or update forward looking information as a result of new information or events after the date of this MD&A except as may be required by law. All forward-looking information disclosed in this document is qualified by this cautionary statement.

SATURN OIL & GAS Q1 2025

MANAGEMENT DISCUSSION & ANALYSIS